RECBWG: Generation Cost Allocation Proposal (20220830)

Throughout the LRTP cost allocation stakeholder process, WEC Energy Group has advocated for the allocation of LRTP (MVP) costs to future generation Interconnection Customers in proportion to the benefits they receive.  We continue to support that position.  We note that the MISO-SPP JTIQ process has developed a proposal for the identification of  Interconnection Customers (both within MISO and SPP) that benefit from the JTIQ portfolio and a proposed $/MW cost allocation that is known early in the DPP process.  A similar process could leverage these JTIQ techniques to allocate a portion of the LRTP costs to all Interconnection Customers that are LRTP beneficiaries.

LS Power Development (LS Power) appreciates the opportunity to offer comments on the Montana Dakota Utilities (MDU) cost allocation proposal. LS Power’s MISO members are transmission developers; therefore, we offer these comments as an entity that would not be directly impacted by this proposal.

Allocating a to-be-determined portion of Multi-Value Project (MVP) costs to generators on a going-forward basis could be beneficial in several respects:

• Recognition that MVPs reduce Network Upgrade costs paid by interconnecting generators
• Acknowledgment that MVPs are needed to reliably support resource transition on a broader scale
• Transfer of costs to the appropriate off-takers, including purchasers of environmental attributes and / or customers located outside of MISO

The to-be-determined portion of MVP costs (X%) likely could not be allocated to existing generators [generators with signed GIAs as of the tariff effective date] under existing FERC precedent. However, in order to be found just and reasonable, and not unduly discriminatory or preferential, X% of MVP costs would likely need to be allocated to all new generators [generators signing GIAs on or after the tariff effective date].

The justification for allocating X% of MVP costs to all new interconnecting generators, as well as to load, is as follows:

• By definition, MVPs provide multiple benefits, not just interconnection to meet public policy goals, as noted in MDU's proposal. This category of projects:
  • Provides economic benefits, including congestion relief
  • Supports long-term system reliability
  • Addresses fleet change more broadly, including retirements of uneconomic generation, and resource-rich areas that wish to export energy or environmental attributes
• An allocation only to renewable resources may be found unduly discriminatory and/or preferential on its face.

Although not specific to MDU’s proposal, we would suggest reconsidering the use of MWh as a billing determinant for the MVP rate more broadly. A rate based on MWh disproportionately impacts high load-factor customers, who are neither causing these additional costs to be incurred, nor receiving commensurate benefits in exchange for a (likely unintended) rate design outcome. Moving to a demand-based or hybrid (demand and usage-based) rate would help to alleviate this imbalance.

Great River Energy offers the following clarifying questions on MDU’s August 30 Generator Pays proposal but is not taking a position on whether to support incorporating a generator allocation into the Multi-Value Project cost allocation methodology at this time.

• Who is billed for intermittent generation – generators or load that owns or has a power purchase agreement with the intermittent generation?
  • If the generator is billed, is there an expectation that they would pass these costs onto the off taker if a power purchase agreement exists?
• How is the weighting factor determined?
• Is the new intermittent generation (MWh) to be charged a forecasted or historical MWh figure?
• Does the cost allocation methodology apply to existing intermittent generation?

WPPI Energy offers responses to the questions posed as follows

1. Do you support incorporating a generator allocation into the Multi-Value Project cost allocation method?

• WPPI supports allocating a portion of new MVP costs to new generator interconnections, which we see as important to provide a price signal for the impact of generator location on resulting transmission costs.

2. As proposed, should the generator allocation apply specifically to new renewable resources?

• In principle, WPPI would support a fuel-neutral cost allocation, though we understand MDU’s rationale for applying costs to renewable resources only, and would agree that this is worthy of discussion.  In any case, WPPI agrees that costs should apply only to new generators, who can make development  decisions with full knowledge of the transmission costs they will entail.

3. Please share other feedback on specific components of the proposal:

  a.  Using Energy (MWh) as the billing determinant for Generators

• WPPI is comfortable using energy as the cost allocation factor

           b.  Application of Generator Allocation Weighting Factor

• The weighting factor provides a degree of freedom in the cost-allocation calculation that may be useful in developing a compromise proposal that can garner broad support

           c.  Others

• WPPI would prefer to see costs assigned primarily to those generators whose siting decisions cause the greatest need for LRTP projects, though we recognize that the MDU proposal represents the most modest sort of change to the existing MVP methodology that could achieve allocation of some costs to generators.

Comments of the Certain MISO TOs in Opposition to Including a “Generator Pays” Component to MISO’s existing Multi-Value Project Cost Allocation Methodology

September 29, 2022

The Certain MISO TOs[1] submit stakeholder feedback in response to the following stakeholder feedback request presented at the August 30, 2022 meeting of the Regional Expansion and Criteria Benefits Working Group (RECBWG).  MISO stakeholders were asked to provide feedback on a Generation Cost Allocation proposal from Montana Dakota Utilities (MDU):

1. Do you support incorporating a generator allocation into the Multi-Value Project cost allocation method?
2. As proposed, should the generator allocation apply specifically to new renewable resources?
3. Please share other feedback on specific components of the proposal:

1. Using Energy (MWh) as the billing determinant for Generators
2. Application of Generator Allocation Weighting Factor
3. Others

Certain MISO TOs’ Stakeholder Feedback:

1. Background

On March 25, 2022, each of the Certain MISO TOs supporting this September 29, 2022 Stakeholder Feedback sponsored written stakeholder feedback to the RECBWG that balanced support for the now-current MVP/LRTP cost allocation methodology with an intent to approach the issues in this RECB stakeholder process with a “fresh perspective and a readiness to engage with other stakeholders to identify a workable path forward.” These Certain MISO TOs continue to engage at RECB with that mindset. 

The Certain MISO TOs today reaffirm the overarching statement made in the March Stakeholder Feedback that “the cost allocation methodology employed by MISO for LRTP projects should be no more ‘granular’ than can be justified through satisfaction of the Commission’s standard cost allocation principles and [MVP] precedent.”  MDU’s August 2022 proposal to make LRTP cost allocation comparatively more granular by including a new intermittent generation (MWh) component in the denominator of the MVP rate calculation (“intermittent generator pays”) to the energy-based usage charge used to recover MVP/LRTP-related costs is not consistent with this high standard.  The Certain MISO TOs oppose including this intermittent generator allocation into MISO’s MVP/LRTP cost allocation methodology.

II. The Certain MISO TOs Oppose MDU’s Proposed Intermittent Generator Pays Component to MISO’s MVP/LRTP Cost Allocation Methodology

The Certain MISO TOs oppose MDU’s proposed inclusion of a more granular “intermittent generator pays” component to MISO’s existing Multi Value Project (MVP) cost allocation methodology. At the outset, the Certain MISO TOs highlight that generators are helping fund transmission upgrades through the MISO cost allocation regime.  The current 90% generator cost allocation for 345 kV facilities, and the 100% generator cost allocation for lower voltage facilities, is a departure from the pro forma approach where all of those costs are typically rolled into rates and not allocated to generators.

MISO’s MVP cost allocation methodology, as it exists today (including the recent inclusion of a subregional cost allocation component to conform to changed circumstances) is a purposeful, elegant, time-tested, and appropriately granular MVP/LRTP cost allocation methodology.  In 2010, MISO and MISO stakeholders made an intentional decision to exclude from the initial MVP cost allocation methodology a mechanism that would have allocated a portion of MVP costs to generators.  The Federal Energy Regulatory Commission (FERC) approved the proposed MVP filing which assigned 100% of MVP costs to load and 0% to generators.  FERC’s orders were subsequently upheld by the 7^th Circuit Court of Appeals. It is important to this discussion to recall that at the same time the MVP cost allocation construct was put in place which does not allocate costs for such projects to generators, the generator interconnection cost allocation methodology was also changed to allocate the majority of costs related to network upgrades associated with such projects to generators.  The current MVP/LRTP cost allocation, which has been upheld by the Court, was correct in 2010, and we see no reason to deviate from this prior approach.

1. MISO, Owners, and Other Stakeholders Intentionally Excluded Generators from MVP Cost Allocation in 2010

MISO and the Owners (“Joint Filers”) presented an overview of stakeholder discussions regarding MVP cost allocation recovery to the Commission in the Joint Filers’ initial, 2010 Transmittal Letter submitted to FERC as part of a filing to create the MVP project category and its related cost allocation methodology.  Among many issues, the Joint Filers described how a proposal to allocate a portion of MVP costs to generators was considered, but ultimately discarded, by the Joint Filers prior to submitting the initial MVP Filing.[2]  The Joint Filers explained in the Transmittal Letter that they chose to allocate 100% of MVP costs to load via an energy-based usage charge applicable only to load, exports, and wheel-through transactions to intentionally encourage the efficient siting of generation projects by assigning the majority of the costs associated with Network Upgrades to the Interconnection Customers that benefit from them.[3]  The Joint Filers specifically intended for generators siting far away from MVPs to bear the cost responsibility associated with its siting decision.[4]  This current cost allocation policy strikes a reasonable balance where load pays for transmission that have broad scope and benefits while generators pay the majority of, but not all of the costs, for local area issues associated with generator interconnection requirements.

As additional support for their decision to intentionally exclude generators from MVP cost allocation, the Joint Filers also relied on the conclusions of an LECG study finding that several unfavorable issues related to energy market distortions would arise should MVP charges be assessed to generators.[5]  The MVP Filing also explained that charging generators for MVPs would cause a double allocation of MVP costs.[6]

1. FERC Approved and the Courts Upheld the Joint Filers’ Proposal to Exclude Generators from the Current MVP Cost Allocation

The Joint Filers’ proposal to exclude generators from MVP cost allocation was a contested at FERC and the issue was taken to the 7^th Circuit.  In the initial FERC order approving the MVP cost allocation proposal, FERC stated with respect to the proposal to allocate MVP costs to load with no allocation to generators that:

[T]he MVP proposal strikes a balance by retaining the existing generator reimbursement policy while allowing a means for generators to mitigate those costs by choosing to site their projects closer to MVP facilities and we will reject the calls for assigning a portion of MVP costs to generators.[7]

After numerous parties subsequently requested rehearing of the Initial MVP Order, FERC issued an order rejecting such rehearing requests, stating that:

In accepting the MVP proposal, FERC approved a methodology in which the costs of new transmission facilities that provide regional benefits are allocated on a regional basis while new transmission facilities required solely for generator interconnection service are allocated to the interconnection customer, which means generators will still receive pricing signals that encourage efficient siting;[8]

Arguments that the MVP cost allocation should assess some costs to generators, because generators benefit from MVPs, ‘take too narrow a view of the cost allocation approved in the MVP Order, which addressed both transmission and generation interconnection;’[9] and    

Nonetheless, parties continued to argue on appeal to the courts that FERC erred by failing to require a “generator pays” component to the MVP cost allocation methodology because failing to charge generators for MVPs sent inappropriate price signals that would lead to inefficient siting, and that FERC erred by imposing all MVP costs on load and none on generators.

The Seventh Circuit of the Court of Appeals upheld FERC’s 2011 Order approving MVPs and associated cost allocation which did not require the allocation of MVP costs to generators.[10]  On the issue of allocating costs to generators, the Court stated that “[a]n important consideration” is that the cost of interconnecting wind farms in remote areas is very high, and reducing these costs using the MVP process would facilitate siting wind farms at the best location, rather than having generators choosing to site them at inefficient locations that are closer to existing grid to reduce costs.[11]

Finally, the United States Supreme Court denied two petitions for writ of certiorari from the 7^th Circuit’s 2013 appellate decision without discussion in orders issued February 24, 2014.[12]

1. Conclusion

Generators are paying for transmission facilities under the current cost allocation approach. At the time the initial cost allocation approach was approved for MVPs, the generator cost allocation was modified to directly assign most interconnection costs to generators, rather than to load.  MDU’s idea proposed at the August 30, 2022 RECB meeting, where new intermittent generators would pay a portion of MVPs, is new in that it would only charge new intermittent generators for MVPs; however, the general idea for charging generators for a portion of MVPs has been debated.  The idea was previously considered for MVP cost allocation and discarded and the Certain MISO TOs see no compelling reason to pursue an alternative cost allocation mechanism at this time. 

*          *          *

DTE appreciates the opportunity to provide feedback to MISO related to the MDU cost allocation proposal.  We commend MDU on their efforts to ensure that LRTP costs are allocated in an equitable manner.  We have the following feedback related to the proposal:

1. Do you support incorporating a generator allocation into the MVP cost allocation method?

Generally speaking, DTE supports a “Beneficiary Pay” based cost allocation for LRTP projects.  Key to achieving this goal is the ability to accurately quantify, measure, and validate the benefits and the associated beneficiaries.  It was not completely clear to us in the examples that were provided how the costs would be allocated to the generators.  We would like a more detailed example to provide us with clarity on how this would be applied in practice.

1. As proposed, should the generator allocation apply specifically to new renewable resources?

To the extent that it can be determined that the net impact of a newly constructed non-intermittent resource increases the transmission build out in the LRTP projects, they should bear some cost responsibility.

MISO RECBWG Feedback

 Big Rivers Electric Corporation

City Water Light & Power (City of Springfield, IL)

Hoosier Energy

Southern Illinois Power Cooperative

RECBWG Draft Cost Allocation Proposal (20220830)

August 30, 2022

Feedback Provided September 29, 2022

Big Rivers, CWLP, Hoosier Energy, and SIPC (“The Respondents”) thank MISO for this opportunity to provide our perspective on the following as presented at the August 30, 2022, RECBWG meeting:

RECBWG: Generation Cost Allocation Proposal (20220830)

In the August 30, 2022, meeting of the Regional Expansion and Criteria Benefits Working Group (RECBWG), Stakeholders were asked to provide feedback on a Generation Cost Allocation proposal from Montana Dakota Utilities:

1)     Do you support incorporating a generator allocation into the Multi-Value Project cost allocation method?

We generally support this concept, recognizing that there are details to be clarified. We think the approach warrants continued consideration and discussion.

2)     As proposed, should the generator allocation apply specifically to new renewable resources?

The generator allocation should apply to new resources.  Any existing resources theoretically would have already paid whatever costs were necessary for interconnection / upgrades through the GIA process.  However, it is not clear to us why the new generator allocation should be limited to renewable resources; presumably new generation using any fuel source could benefit from the LRTP projects, and if those resources have not yet paid costs pursuant to a GIA, they should pay for LRTP projects.

3)     Please share other feedback on specific components of the proposal:

           a.  Using Energy (MWh) as the billing determinant for Generators

Energy should not be the billing determinant for any transmission project, including generators and load.  Transmission costs are demand-related and do not vary with the amount of MWh consumption by LSEs or MWh production by generators.  This is a fundamental cost of service and rate design principle, consistent with the NARUC Electric Utility Cost Allocation Manual.  We believe the current MVP reliance on energy as a billing determinant is inappropriate and it would be improper to continue that approach by using energy as a billing determinant for generators.  Transmission costs should be billed on demand.

           b.  Application of Generator Allocation Weighting Factor

This concept merits further consideration and discussion. 

           c.  Others

We agree with MDU that not all states and loads are equal cost causers and beneficiaries.  As such we believe that using the postage stamp across the entire MISO footprint or across the MISO North/Central subregion fails to allocate costs of MVPs in a manner “at least roughly commensurate” with estimated benefits.

We do not necessarily agree with MDU that one benefit of the proposal is “ease of administration” because even though there would be “one MVP rate for load and generation,” MISO would have to separately track the new intermittent generation from the existing generation and apply the rate to only the new generation.  This could prove to be an administrative burden.

Overall we are generally supportive of the concept and believe that further discussion of the advantages, disadvantages, and details is warranted.

 Thank you in advance for considering this feedback.

Apex Clean Energy (“Apex”) appreciates the opportunity to provide comments on the Generation Cost Allocation Proposal (the “Proposal) presented by Montana-Dakota Utilities Co. (“MDU”) to the Regional Expansion and Criteria Benefits Working Group (“RECBWG”) on August 30, 2022.

 Apex does not support the Proposal.  While we understand MDU’s statement that “not all states and loads are equal cost causers and beneficiaries,” the Proposal is discriminatory against new intermittent generators and is not just and reasonable.  Further, the presentation by MDU at the RECBWG meeting on August 30, 2022 was not supported by any data and it seems to be based solely on the argument that generators should pay some portion of the costs of the Long Range Transmission Plan (“LRTP”) projects.  Please see the attached document for our further, more detailed comments.

Apex Clean Energy

 ENVIRONMENTAL SECTOR COMMENTS ON MDU GENERATOR PAYS PROPOSAL

The Environmental Sector^[1] submits the following comments responsive to the feedback request concerning MDU’s August 30th presentation to MISO RECB working group.

1. MISO Question:  Do you support incorporating a generator allocation into the Multi-Value Project cost allocation method?

No. At the August 30th RECB meeting, MDU cloaked its ill-conceived proposal in a thin veil of reasonable compromise. MDU’s proposal is ill-conceived because (1) it ignores the historical generator/load compromises that were intended to act in tandem and (2) it incorrectly assumes LRTP is a generation-outlet initiative instead of a reliability initiative.

First, MDU’s proposal ignores the historical context of how MVP cost allocation came to be and the tradeoffs that were made. The original MVP cost allocation discussions fully considered a generator pays aspect but ultimately decided not to include one. We note, as described in a recent presentation to OMS, that none of the other RTOs charge generators for regional upgrades, but similar to MISO, many charge them for interconnection related network upgrades^[2]. Even assuming MDU’s proposal would pass the “reasonably commensurate” threshold for cost allocation, which is dubious,^[3] if MISO is going to include cost allocation of MVP projects to generators based on anticipated benefits, then it must conversely allocate the costs of interconnection network upgrades to non-generators that benefit from those projects.

The compromise that was made when the MVP tariff was initially drafted to not include a generator pays element resulted in generators paying for 100% of all required interconnection network upgrades below 345kV and 90% of any such upgrades 345kV and above, despite expectations that these network upgrades also bring benefits - in some cases significant - to load. This compromise was a sort of “rough justice” that does not include specific analysis of the benefits of individual lines, but it was sufficient to attract a critical mass of stakeholder support while meeting minimum legal thresholds. The compromise reached in 2011 to secure cost allocation methodology for MVP lines remains codified in the existing cost allocation methodologies for both MVP and interconnection projects. Any proposal to undo one element of this compromise must, therefore, include reevaluation and negotiation of the other. 

We also note another issue in play in the MISO stakeholder process that must be included in any meaningful consideration of new cost allocation constructs that share costs among generators and load. A proposal currently being considered in the Interconnection Process Working Group and Planning Subcommittee that would modify the GIP threshold to lower the DFAX from 20% to 10% for ERIS interconnection customers, exposing them to increased interconnection costs that are designed to reduce congestion and likely provide benefits to more than just the interconnecting generator. The Environmental Sector opposes that effort because, if adopted, it would be another unreasonable shift of costs for grid upgrades to generators. This is on top of the fact that generators along the seam with SPP may also be responsible for 90 percent of the costs associated with any 345kV JTIQ lines that will bring regional benefits to non-generators, or are otherwise responsible for affected systems studies costs to the extent they are far enough advanced in the interconnection queue.

MDU’s proposal cannot be considered in a vacuum. It must be considered in the context of MISO’s full cost allocation construct that ultimately strikes a balance in allocating costs among generators and load. MDU’s proposal may seem reasonable on its own to some, but in the context of MISO’s entire approach to cost-allocation, any LRTP cost allocation methodology that would expose generators to greater costs is inappropriate, particularly given the scope of MISO’s Reliability Imperative and LRTP’s stated purpose to increase regional reliability. Considering the interrelationship between cost allocation methodologies for various types of projects, we don’t believe it is possible for MISO to consider the additional allocation of costs to generators, including for MVPs, without materially upsetting the balance that was struck when the original DPP and MVP allocation arrangements were made. At a minimum, the addition of a generator allocation into the MVP tariff must be accompanied by a redesign of the 100 percent and 90/10 cost split for generation interconnection network upgrades and reconsideration of the DFAX thresholds used to trigger interconnection costs in the DPP.

2. MISO Question:  As proposed, should the generator allocation apply specifically to new renewable resources?

No. Applying a generator allocation only to new renewable resources would be unduly discriminatory, or otherwise subject new renewable resources to undue prejudice or disadvantage, per Sections 205 and 206 of the Federal Power Act. MDU’s proposal seems to be based on the assumption that LRTP is a generator outlet study for renewables, which is not accurate. Regional reliability is the primary goal of LRTP while congestion reduction is one of many secondary benefits. 

While we note above that we do not support a generator pays aspect to the MVP methodology, any charge for LRTP lines to generators should recognize that all new and existing generators will likely benefit from a more robust and resilient grid. Arbitrarily assigning costs to new renewable resources simply because they make up the majority of new resources is inappropriate and likely unlawful.

The MDU Proposal also exempts new non-intermittent resources, because it claims that such resources provide “24x7 support of the transmission system and can avoid or minimize need for LRTP projects” (slide 6). We disagree with this rationale.

First, part and parcel with reliability is resilience, which recognizes extreme weather as a serious factor necessitating large-scale and atypical flows of power across the grid. Winter Storm Uri showed just how beneficial transmission is during such events, as very large amounts of power flowed in atypical directions in order to direct power to regions where generation that MDU claims to provide “24x7” support was literally frozen and unable to power up. While thus far such events are fortunately rare, their impact can be and has been enormous. These expensive tail-end events are also more likely to occur due to climate change. Thus, it is unreasonable to say that non-intermittent resources do not benefit from LRTP lines or can avoid the need for them.

Second, the claim that non-intermittent resources “can avoid or minimize the need for LRTP projects” ignores the fact that such resources are generally more expensive than the sum of intermittent resources plus transmission. It appears here that the MDU Proposal suggests building more non-intermittent resources to meet MISO’s reliability goals, but this ignores the fact that this arrangement would ultimately result in higher costs to ratepayers, and thus could be seen as being unjust and unreasonable, in addition to being unduly discriminatory.

In sum, while we appreciate MDU’s efforts to contribute to the cost allocation discussion and MISO’s role in allowing stakeholders to review MDU’s proposal, we believe that this proposal does not merit any further discussion because it is so clearly discriminatory and ill-conceived for the reasons stated above. We expect any final cost-allocation construct to treat all resources in a non-discriminatory manner with benefits and costs assigned based on robust analysis and sound reasoning.

3. MISO Question:  Please share other feedback on specific components of the proposal:

1. Using Energy (MWh) as the billing determinant for Generators
2. Application of Generator Allocation Weighting Factor
3. Others

Because we believe that the basis of this proposal is both unduly discriminatory and unjust and unreasonable, we decline to comment on the specific components of MDUs proposal since any adjustment would still be based upon false or arbitrary reasoning. 

1. Do you support incorporating a generator allocation into the Multi-Value Project (MVP) cost allocation method?

Pine Gate Renewables (PGR) cannot support MDU’s proposal to incorporate a generator allocation in the MVP cost allocation method for the following reasons:

a. The proposed cost allocation methodology change would impact cost allocation for all MVPs – including base reliability projects, market efficiency projects, and replacements. Based on Attachment FF to the Midcontinent Independent System Operator, Inc. (MISO) Tariff, a revision to the MVP cost allocation methodology would have impacts that reach far beyond the impacts presented in the proposal. MVPs can be identified under 1 of 3 criteria including base reliability
needs and market efficiency, both of which fall squarely within the responsibility of transmission owners and are unlikely to benefit interconnecting generators.¹

Further, MVPs can include like-for-like capital replacements of plant originally installed as part of a MVP where replacement is due to aging, failure, damage, or relocation.² Such replacements are not even subject to the minimum capital cost typically required for a MVP³. A generic change to the MVP cost allocation methodology would also allocate costs/benefits associated with these to new intermittent generators – although the previous MVP had not assigned benefit or costs to
generators, whether or not yet constructed.

Simply put, a wholesale change to the cost allocation methodology for MVPs to require that new intermittent generators be assigned a pre-defined allocation of the benefit/cost of such projects would not only affect Long Range Transmission Planning (LRTP) projects. it would also affect any qualifying market efficiency or base reliability need projects that qualify for and are classified as a MVP, including a replacement for a previously installed MVP for which no generator benefit had
been identified or allocated. Effectively, through the proposal to pre-assign a set percentage of MVP- related costs/benefits to new intermittent generators, Montana Dakota Utilities (MDU) is asking MISO to assign new intermittent generators a portion of the cost/benefit for all MVPs – regardless of whether they are base reliability projects, market efficiency projects, or replacements of MVPs due to aging, damage, failure, etc., and regardless of the benefit determinations.

It has long been a tenet of good utility practice and a requirement of transmission owners and providers to take responsibility for the current and future state of the transmission system it owns and operates. The cost allocation and benefit assignment proposed by MDU does not comport with these tenets nor the tenets of cost causation and benefit receipt. At a minimum, no portion of the costs to build or the benefits derived from a base reliability project or replacement of a MVP
project should be assigned to new intermittent generation - especially where such generation was not constructed/is not constructed, and for which operational characteristics are unknown.

That the generation allocated these costs/benefits would receive no direct benefit, and would not be a cost causer for more than 1 type of MVP further underscores the unjust and unreasonable nature of MDU’s proposal.

Given the broad classes of projects that can be identified as MVPs, a wholesale change to the MVP cost allocation methodology would be inappropriate. The far- reaching consequences of MDU’s proposal cannot be justified through a generic statement that generators have received or will receive benefits from LRTP projects.

b. The allocation would be inconsistent with the objectives of the LRTP when it was proposed as part of the Reliability Imperative, which were: … to provide an orderly and timely transmission expansion plan that supports these primary goals:

• Reliable System – maintain robust and reliable performance in future conditions with greater uncertainty and variability in supply
• Cost Efficient – enable access to lower-cost energy production
• Accessible Resources – provide cost-effective solutions allowing the future resource fleet to serve load across the footprint
• Flexible Resources – allow more flexibility in the fuel mix for customer choice.⁴

None of these objectives is geared towards the interconnection of specific resources or classes of resources. Indeed, it is important to note that the same report provided that “LRTP is designed to assess the region’s future transmission needs in concert with utility and state plans for future generation resources.”⁵ Hence, assigning only one class of resource costs/benefits (regardless of the inclusion of other resource classes in applicable utility or state plans) is inconsistent with the underlying objectives of the LRTP process.

c. Any proposed generator weighting or allocation to a specific resource class only would be inconsistent with the specific metrics used to determine the economic benefits of MVPs and MVP portfolios on a going forward basis. The metrics identified include, but were not limited to⁶:
• Congestion and fuel savings – LRTP projects will allow more low-cost renewables to be integrated, which will replace higher-cost resources and lower the overall production cost to serve load.
• Avoided local resource capital costs – LRTP projects will allow renewable resource buildout to be optimized in areas where they can be more productive compared to a wholly local resource build out.
As proposed, an assigned weighting applied solely to new intermittent generation negates any benefits that are determined to be attributable to such generators, e.g.,  fuel cost savings, and, further, assumes that no other resources receive any benefit from any of the identified metrics. These blanket assumptions would effectively “trump” the actual benefit analyses required to be conducted and would result in a cost allocation that does not follow benefits identification.

The MVP process must continue to follow and implement a comprehensive and realistic benefits determination. In any market that relies upon a diverse resource mix, the premise that ONLY a particular class of resources benefit from decreased congestion, decreased fuel costs, reduced resource adequacy requirements, etc. is unrealistic and must be rejected.

d. The proposed allocation is inconsistent with the benefits that have been shown to result from LRTP Tranche 1. Consistent with the “least regrets” approach with which the LRTP element of the Reliability Imperative was designed and implemented, the benefits resulting from the LRTP Tranche 1 were attributed, in large part, to congestion and fuel savings with the second largest portion attributed to avoided capital costs of local resource investment.⁷ Indeed, for the congestion and
fuel savings benefit, the inclusion of intermittent resources in the calculation of this benefit resulted in significant savings for load-serving entities. As well, for the second largest element, a large portion of the savings was attributed to the ability to deliver resources from one area in the footprint to another. This makes clear that benefits from the LRTP projects result – regardless of the fuel source and location of the resources used (for Avoided Capital Cost of Local Resources).

Interestingly, despite MDU’s assertions in its presentation, there is no indication in the MTEP 21 Addendum that supports the assertion that, of generation resources, only new intermittent generation would benefit from LRTP projects. Also, there is no indication that new intermittent generation alone would be the sole cost causer for LRTP projects. This is curious as there are current interconnection requests for conventional generation, e.g., gas, diesel, coal, etc., in the interconnection queue. If MDU and MISO seek to exclude conventional resources as receiving any benefits or as cost causers, they must demonstrate that none of these projects nor any other
future-queued conventional resource would benefit from LRTP projects and that they do not negatively affect the benefit metrics (e.g., fuel cost savings). Without this showing, no resource class should be unilaterally exempted from the required benefit calculations or associated cost allocations.

e. MDU’s proposal appears to address a perceived inequitable distribution of costs of the LRTP projects. However, the benefits distribution depicted in Figure 8.1 of the MTEP 21 Addendum clearly shows that all zones had extremely close benefit distributions - including Zone 1, where MDU is located, which had one of the higher max benefits.⁸ At a minimum, if MDU’s concern is that it has been inequitably assigned costs and its goal is to further ensure the equitable distribution of costs, a review of the benefit metrics and methods by which such are identified and calculated should be undertaken to determine if revisions are necessary to the benefits determinations. Rather than trying to revise the cost allocation method such that it assigns costs independent of and without support from the benefits determination, MDU should seek a review of the benefits metrics and methodology as such would be the most appropriate starting point to address their concerns.

f. MDU’s proposal includes no support on which to exclude or include certain classes of resources. It also requires a presumption of cost causation and benefits receipt that was not identified in the published data supporting Tranche 1 and that is inconsistent with the objectives of the LRTP process. MDU and any other transmission owner would oppose a cost allocation methodology that, without substantive data in support, ignored the benefits evaluation and assigned a pre-calculated
cost allocation or level of benefits. Such opposition would be even stronger where the methodology: (1) was potentially discriminatory, and (2) would be effective for all future portfolios or allocations.

PGR agrees that such a methodology would be inherently arbitrary and capricious, and potentially discriminatory – especially where it was applied in a manner that ignored other stakeholders or resource classes, benefit determinations, and cost causation principles.

Just as MDU (or any other transmission owning member) would not want to have a preset percentage of cost assigned to it for all future LRTP tranches regardless of the actual benefits determination, it should not be seeking to foist the same on any other stakeholders. The cost allocation proposal is contrary to what would be acceptable to any stakeholder. It provides preference to specific classes of resources and assumes unsubstantiated benefits/costs. It should not be pursued.

2. As proposed, should the generator allocation apply specifically to new renewable resources?

No. PGR opposes any cost allocation methodology that negates benefit determinations performed, ignores cost causation attributable to other generating resource classes, gives preferential treatment to a specific class of resources, and discriminates against specific classes of resources. As stated above, the current benefits determination addresses all resources – not just intermittent resources - and MDU has failed to provide any evidence to support its premise that traditional resources do not benefit from the LRTP projects – especially relative to reduced congestion costs, a benefit which applies across the footprint and across resources without regard
to fuel source.

3. Please share other feedback on specific components of the proposal:
a. Using Energy (MWh) as the billing determinant for Generators
b. Application of Generator Allocation Weighting Factor?

PGR has no comments to provide in response to this question as it opposes the MDU proposal for cost allocation.

However, PGR notes that it is concerned with how the administration of this new cost allocation, if filed and approved, would occur. There are several unknowns regarding how the costs allocated to new intermittent generation would be identified (through bilateral and power purchase agreements?), assigned, and collected. As well, PGR is concerned regarding the timing within which this or any other new cost allocation, if approved, would be applied. PGR strongly opposes any retroactive application of this cost allocation methodology. Finally, PGR notes that new intermittent generation may have entirely different operational characteristics that are not considered or accounted for in this cost allocation methodology. As technological advances occur, e.g., grid forming inverters, synthetic inertia, etc., intermittent generation will have operational characteristics that are more like conventional resources. The cost allocation methodology proposed by MDU would not allow for consideration of those advances and would continue to provide preferential treatment to conventional generation despite similar operational characteristics or benefits being available from and provided by intermittent resources.

1 MISO Tariff, Attachment FF, at II.C.3.
2 Id. At II.C.6.
3 Id.

4 See MTEP21 REPORT ADDENDUM: LONG RANGE TRANSMISSION PLANNING TRANCHE 1 EXECUTIVE SUMMARY

(MTEP 21 Addendum) at MTEP21 Addendum-LRTP Tranche 1 Report with Executive Summary625790.pdf
(misoenergy.org), p. 13.
5 Id.
6 Id. At p. 16.

7 Id. At Figure 7.1 (p. 47).

8 Id. At Figure 8.1 (p. 69).

The OMS Transmission Cost Allocation Work Group appreciates MDU’s proposal submitted to the MISO RECBWG on August 30, 2022. We understand that there are several cost allocation proposals currently under consideration. As such, we do not take a position on the MDU proposal at this time.

We look forward to further discussions with MISO and stakeholders to develop a cost allocation methodology that recognizes the OMS position that “[g]enerators and load each can be considered cost causers, beneficiaries, or both and should be allocated costs accordingly.” OMS Cost Allocation Principles Committee, Principle No. 4. MISO should ensure stakeholders have opportunities at future RECBWG meetings to discuss these methodologies and how best to assess beneficiaries.

This feedback is from an OMS work group, and it is not a formal response of the OMS Board of Directors.

American Municipal Power (AMP) submits the following feedback:

AMP supports comments submitted by WPPI, with a clarification on how “new” generator interconnections are defined. AMP supports allocating a portion of new MVP costs to new generators that are in a generator interconnection queue cycle that closes after the effective date of the proposed Tariff change.

Entergy Feedback to RECBWG on Generation Cost Allocation Proposal

September 29, 2022

The following feedback is offered by the Entergy Operating Companies ("EOCs")[1]  in response to MISO’s request in the August 30, 2022 meeting of the Regional Expansion and Criteria Benefits Working Group (RECBWG) for stakeholders to provide feedback on the following questions regarding a Generation Cost Allocation proposal from Montana Dakota Utilities (“MDU”):

1. Do you support incorporating a generator allocation into the Multi-Value Project cost allocation method?
2. As proposed, should the generator allocation apply specifically to new renewable resources?
3. Please share other feedback on specific components of the proposal:
   a.  Using Energy (MWh) as the billing determinant for Generators
   b.  Application of Generator Allocation Weighting Factor
   c.  Others

Introduction

The EOCs generally support the continued exploration by MISO and its stakeholders of how to incorporate “generator pays” concepts into current and future cost allocation methodologies.  However, while we remain interested in working with other participants on expanding cost allocation to eventually incorporate the assignment of LRTP-related costs to new generating facilities that benefit from those projects, the EOCs are unable to support MDU’s current proposal for the reasons articulated below.  The EOCs appreciate MDU’s efforts to develop a novel proposal that helps advance the discussion around these issues.  It is in the same spirit that we offer our comments below.

1.  Do you support incorporating a generator allocation into the Multi-Value Project cost allocation method? 

Yes.  While the creation of a more granular overall cost allocation methodology remains the EOCs’ top priority relative to LRTP Tranche 3, Entergy appreciates that the MDU proposal seeks to increase the granularity of the allocation to future resources which will benefit from LRTP projects.

However, the EOCs continue to have concerns with postage stamp allocation of charges for regionally and sub-regionally cost allocated transmission projects.  Entergy may support a proposal with a zonal component to it, like what has been proposed in the JTIQ process, but on a more granular level than just a MISO North zone and a MISO South zone, such as by Cost Allocation Zones.  For example:

• MISO uses an “Unknown Owner” category in PROMOD for some of the Future generation. This could be expanded to have an unknown owner group in every CAZ, which we believe would show a more granular view of the benefits that may be attributed to future generation.
• MISO identifies “LRTP enabled generation” as part of the benefit calculation for the Tranche 1 portfolio and is expected to do the same for future LRTP portfolios.  Perhaps the “LRTP enabled generation” could be leveraged to assign cost to zones for future resources.

2.  As proposed, should the generator allocation apply specifically to new renewable resources?

No; Entergy disagrees with excluding “conventional” resources from the cost allocation.   Conventional resources seeking interconnection service will also benefit from the increased network capacity. 

3.  Other feedback on specific components of the proposal:
           a.  Using Energy (MWh) as the billing determinant for Generators

The proposal is interesting, but the proposed postage stamp approach to generators incorrectly equates changing usage to changing benefit and it violates the cost causation principle of allocating costs commensurate with benefits by assigning costs to generation that does not actually stand to benefit from the new transmission, in that it assumes that all generators will benefit equally from all LRTP transmission, which is not likely to be the case. MISO’s own analysis of LRTP Tranche 1 benefits suggests that benefits of the LRTP portfolio will not be spread evenly, with zonal benefit/cost ranging from 2.2 to 4.4, yet all customers will pay the same rate for LRTP transmission, regardless of what benefits have been identified for the area in which they are located.

    b.  Application of Generator Allocation Weighting Factor

The weighting factor component is not immediately clear.  Further explanation by MDU on how it would be determined is required to better understand this area of the proposal.

           c.  Others

Another challenge that should be addressed in the development of a proposal to allocate costs of LRTP projects to generators is the uncertainty of exact future resource siting and how much of the upgrade costs future resources should be allocated going forward.  The JTIQ proposal for the former issue is untested as of yet, and further technical analysis would be a good next step in this process.

The EOCs appreciate the opportunity to comment.

Do you support incorporating a generator allocation into the Multi-Value Project cost allocation method?

Yes, generators stand to benefit from backbone system upgrades identified through MVP/LRTP planning and should share in the costs of these projects.

As proposed, should the generator allocation apply specifically to new renewable resources?

Renewable as well as non-renewable generation stands to benefit from MVP/LRTP projects and both should be considered in applying costs to generators.

Please share other feedback on specific components of the proposal:
           a.  Using Energy (MWh) as the billing determinant for Generators
           b.  Application of Generator Allocation Weighting Factor
           c.  Others

Alliant Energy appreciates the proposal and creative thinking with the Generation Cost Allocation proposal from Montana Dakota Utilities but believes non-renewable generation as well as renewable generation should be considered in allocating MVP/LRTP costs to generators. A MWh or MW billing determinant could be used in allocating cost to generators and Alliant Energy is open to exploring further both of these potential billing determinants.  Given the potential complications of creating a method to allocate costs to generators Alliant Energy sees value in keeping the method used to allocate costs to generators to be straightforward and predictable.  Alliant Energy looks forward to additional stakeholder discussions on this topic.